Reservoir Quality Research Articles

Carbonate reservoir characterization and permeability modeling using Machine Learning ـــ a study from Ras Fanar field, Gulf of Suez, Egypt

Predicting facies and petrophysical properties along and between wells is challenging in carbonate reservoir modeling. In the Nullipore carbonate reservoir, Ras Fanar field, depositional and long-term diagenetic processes result in a high degree of heterogeneity and complex distribution of facies, which in turn affect the reservoir quality. This provides a significant obstacle to building accurate geological models. This study integrates thin sections, routine core analyses, and well logging data to overcome such difficulties and model the Nullipore carbonate facies and permeability. The detailed petrographic analysis revealed the existence of seven microfacies in the reservoir, which are summed up into three facies associations (FAs), each of which represents a specific reservoir rock type (RRT): (1) supratidal FA, (2) intertidal FA, and (3) shallow subtidal FA. The three FAs were correlated with the gamma-ray logs to create facies logs for the studied wells, which were further populated via the Truncated Gaussian Simulation method. Cross-validation was used to evaluate the model's accuracy. The analysis of the available core data infers that the three RRTs are prospective and have a wide permeability distribution. However, RRT3 constitutes the best reservoir quality. The sedimentological analysis revealed that the long-term diagenetic events, involving the dolomitization of limestone and the dissolution of allochems have a major role in improving the pore connectivity and permeability of the reservoir. Fracture characterization discloses that fractures play a significant role in fluid storage and migration. Three Machine Learning (ML) models, including Adaptive boosting (AdaBoost), Gradient Boosting (GB), and Extreme Gradient Boosting (XGB), were developed to integrate the RRTs, porosity, and permeability to improve permeability prediction. Statistical analysis revealed that the XGB model outperforms other models and exhibits the highest prediction performance. The present study provides further insights into the characterization and modeling of facies and permeability of complex carbonate reservoirs. It can be applied in similar geological settings to better interpretation of depositional and diagenetic controls on reservoir quality assessment and aid in the field development plan.

Porosity Prediction Based on Ensemble Learning for Feature Selection and an Optimized GRU Improved by the PSO Algorithm

Accurate and reliable prediction of porosity forms the foundational basis for evaluating reservoir quality, which is essential for the systematic deployment of oil and gas exploration and development plans. When data quality of samples is low, and critical model parameters are typically determined through subjective experience, resulting in diminished accuracy and reliability of porosity prediction methods utilizing gated recurrent units (GRU), a committee-voting ensemble learning (EL) method, and an enhanced particle swarm optimization (PSO) algorithm are proposed to optimize the GRU-based porosity prediction model. Initially, outliers are eliminated through box plots and the min–max normalization is applied to enhance data quality. To address issues related to model accuracy and high training costs arising from dimensional complexity, substantial noise, and redundant information in logging data, a committee-voting EL strategy based on four feature selection algorithms is introduced. Following data preprocessing, this approach is employed to identify logging parameters highly correlated with porosity, thereby furnishing the most pertinent data samples for the GRU model, mitigating constraints imposed by single-feature selection methods. Second, an improved PSO algorithm is suggested to tackle challenges associated with low convergence accuracy stemming from random population initialization, alongside the absence of global optimal solutions due to overly rapid particle movement during iteration. This algorithm uses a good-point set for population initialization and incorporates a compression factor to devise an adaptive velocity updating strategy, thereby enhancing search efficacy. The enhanced PSO algorithm’s superiority is substantiated through comparison with four alternative swarm intelligent algorithms across 10 benchmark test functions. Ultimately, optimal hyper-parameters for the GRU model are determined using the improved PSO algorithm, thereby minimizing the influence of human factors. Experimental findings based on approximately 15,000 logging data points from well A01 in an operational field validate that, relative to three other deep learning methodologies, the proposed model proficiently extracts spatiotemporal features from logging data, yielding enhanced accuracy in porosity prediction. The mean squared error on the test set was 7.19 × 10–6, the mean absolute error stood at 0.0082, and coefficient of determination reached 0.99, offering novel insights for predicting reservoir porosity.

Formation mechanism and implication of analcime in the sandstone reservoirs of the Permian Jingjingzigou formation in the Jinan sag, southern Junggar basin, NW China

Analcime plays a significant role in sandstone reservoirs as an authigenic diagenetic mineral in the Junggar Basin (northwestern China). However, the origin and controls on the reservoirs have received remarkably little attention. This study investigates the formation mechanism of analcime in the Middle Permian strata in the Jinan sag (southern Junggar Basin) through petrography and geochemistry. The results show that analcime is formed through early alkaline hydrolysis of volcanic materials under specific temperature and pressure conditions. The reservoir rocks primarily consist of various lithic sandstones, including volcanic debris such as basalt, andesite, and tuff. Analcime is characterized as rich in aluminium and poor in sodium, classified as low-silica analcime with a low Si-Al ratio (1.98–2.38). Furthermore, various other diagenetic minerals, such as glauconite, chlorite, albite, and calcite have been identified. The primary reservoir space chiefly consists of intragranular dissolved pores of analcime, while secondary pores are formed by intragranular pores of feldspar and lithic, along with some remaining intergranular pores. Cementation of analcime during early diagenesis changes primary pore structures and reduces reservoir properties. The low-silica analcime dissolves due to acidic pore fluids associated with three stages of oil and gas charging, transforming into albite and creating numerous secondary pores, thereby enhancing reservoir quality.

Reservoir heterogeneities due to diagenesis in Jurassic Samana Suk Formation Kahi section Nizampur Basin North West Himalayas Pakistan

The porosity and permeability determine the reservoir quality of sedimentary rocks, which is fundamentally influenced by both depositional and diagenetic processes. The Jurassic carbonates are targeted in many regions for oil and gas exploration. The current study is carried out to elaborate on the diagenetic alterations and their effect on reservoir properties. A thick outcrop of the Jurassic Samana Suk Formation is studied in the Kahi section of Nizampur Basin Northwest Himalayas, Pakistan, to study and relate the trend of lithological variations and depositional settings. Field investigation revealed that the Samana Suk Formation is extensively distributed in the area and primarily made up of interbedded limestone and dolomite units. The original unaltered limestone has a thick-bedded and oolitic to bioclastic nature. Different types of dolomites have been recognized based on colour contrast and sedimentary features. Moreover, saddle dolomite cement, calcite cementation, and mechanical and chemical compaction have also been observed. The petrographic studies show different types of diagenetic alterations that affected the Samana Suk Formation, including micritization, bioturbation, mechanical and chemical compaction in the form of fractures and stylolites, various calcite cementation, which includes the various cement types that range from isopachous, blocky, granular equant, fibrous, and dog tooth cementation, along with dissolution that occurred in different diagenetic realms. Pyritization was rarely observed. Moreover, different phases of dolomites were identified, ranging in size and shape, i.e., finely crystalline to coarse crystalline and planar euhedral to non-planar anhedral. The stable oxygen isotope values of these dolomites show depletion from original marine signatures and suggest burial-related fault-controlled dolomitization events. Overall, diagenetic processes like dissolution, fracturing and dolomitization increased the reservoir potential. On the contrary, the overburden and cement precipitation result in a decrease in the reservoir properties.

Improved reservoir quality assessment by evaluating illite grain coatings, quartz cementation, and compaction – Case study from the Buntsandstein, Upper Rhine Graben, Germany

Reservoir quality (RQ) in the Buntsandstein of the Upper Rhine Graben is in the center of attention as it is a possible target formation for geothermal energy production and hydrocarbon exploration surrounding existing fields. An understanding of properties affecting reservoir quality of the target lithology is still fairly poor and the success of accurately targeting high RQ intervals is limited. This is due to the fact, that the effect of compaction and the interplay between enhanced chemical compaction (i.e. pressure dissolution of quartz grains), illitic contact coatings and quartz cementation in the lithology has been underestimated. The understanding and quantification of controlling factors on reservoir qualities in fluvio-eolian sedimentary rocks, deposited in a (semi-)arid climate has been improved in recent years and this case study highlights the benefits of detailed petrographic analyses in understanding diagenetic and compactional processes in this lithology. This is especially relevant in the observation of grain coating clay minerals, whose effect depends on their specific location, i.e. either at grain contacts between quartz grains (GTG coating) or at the interface between detrital quartz grains and the intergranular volume (GTI coating).Illitic GTI coatings affect syntaxial quartz overgrowth precipitation, as precipitation sites are locally blocked. The negative correlation between the grain coating coverage and quartz cement volumes support these findings across multiple sample sets, and they may locally preserve intergranular porosity. Illitic GTG coatings on the other hand enhance chemical compaction (i.e. pressure dissolution) and will reduce the IGV. The negative correlation between these two properties again underlines the negative effect of this process on reservoir properties. Studied samples from a deep Buntsandstein well in the central URG show low reservoir quality due to either intense quartz cementation (0.7–31.7%) or a high degree of mechanical and chemical compaction (IGV: 2.3–38.0%). Higher illitic GTG and GTI coating coverages play a substantial role in controlling reservoir quality development, as demonstrated by comparing data from other fluvio-eolian lithologies (Triassic Buntsandstein and Permian Rotliegendes) to results of this study. In relation to their respective burial histories, higher illitic GTI coating coverages always correlate with smaller syntaxial quartz cement volumes. Similarly, higher illitic GTG coating coverages always correlate with lower IGV values in the three compared sample series.As both, the precipitation of quartz cements and compaction, are a function of the burial history, i.e. effective stresses and experienced temperatures, understanding the interaction of both these processes may enable the prediction of reservoir properties in undrilled areas.

Impact of clay minerals on reservoir sandstone properties: comparative study in Colombian eastern cordillera and middle Magdalena valley basins

The aim of this study is to examine how mineralogy influences the petrophysical properties, particularly porosity and permeability, of potential sandstone reservoirs in Colombia. It seeks to comprehensively understand how the presence of clay minerals impacts the overall quality of hydrocarbon reservoirs in the country. Samples of sandstones from reservoirs at various outcrops in the Eastern Cordillera and Middle Magdalena Valley basins were collected. Detailed analysis of mineralogy and petrographic characteristics of the samples was conducted through various analytical techniques such as transmitted light microscopy, X-ray diffraction, and scanning electron microscopy. Porosity and permeability were measured using automated permeametry and porosimetry equipment. The predominant composition of the analyzed reservoir rocks comprises quartz (45-50%), feldspar (35-40%), and clays (10-20%). These rocks were categorized into two distinct groups based on their permeability (K) and porosity (Φ), ranging from 0.009 to 29.220 mD and 1.88 to 20.75%, respectively. The presence of illite correlated with a reduction in both porosity and permeability, highlighting its negative impact on reservoir quality. Conversely, an elevated concentration of kaolinite was associated with favorable porosity and permeability. Samples with feldspar sericitization demonstrated inferior hydrocarbon storage quality. This study provides a deeper understanding of how mineralogy affects the petrophysical properties of sandstone reservoirs in Colombia. These findings are crucial for guiding exploration and production strategies in the Colombian oil industry, especially in challenging geological environments like those studied.

Lithofacies assemblage and effects on diagenesis in lacustrine tight sandstone reservoirs: Samples from Upper Triassic Yanchang Formation, Ordos Basin, China

Lacustrine basins are rich in unconventional oil and gas resources and the heterogeneity of matrix reservoir quality seriously affects its development. Previous studies have recognized that diagenesis is the key factor affecting the heterogeneity of matrix reservoir quality, but diagenesis controlled by lithofacies assemblages is poorly studied. In this study, tight sandstones in the Triassic (Ladinian-Carnian) Chang 7 Member of Ordos Basin were taken as examples. Lithofacies, lithofacies assemblages, diagenesis evolution and distribution were investigated by casting thin section analysis, scanning electron microscopy (SEM), X-ray diffraction (XRD), fluid inclusion and carbon-oxygen isotope. The results indicate that eight lithofacies assemblages in Chang 7 exhibit variations in lithofacies, sand-mud ratio and grain size rhythm, controlling the distribution and intensity of diagenesis. Variations in average proportion of lithofacies assemblages are linked to lake level cycles. Compared to cementation, the mechanical compaction has a higher adverse effect on primary porosity of tight sandstones in Chang 7. Siltstone lithofacies show stronger compaction and cementation (mainly clay cementation), whereas fine sandstone lithofacies exhibit stronger dissolution, especially FSpc (fine sandstone with parallel or cross-bedding). Modest proportions of illite (<4%) and chlorite (<1.5%) in fine sandstones tend to form clay coatings, resisting compaction and preserving more porosity. Conversely, abundant pore-filling illite (>4%) and chlorite (>1.5%) result in a noticeable decline in porosity. Particle size and sorting affect reservoir quality by controlling compaction strength. The origin of carbonate cement in sandstones is closely related to mud-rich lithofacies within lithofacies assemblages. Carbonate cementation preferentially occurs in fine sandstones within 0.4 m from the sand-mud interface and the thickness of adjacent mud-rich lithofacies is greater than 0.1 m. Interfaces between fine sandstones serve as fluid migration pathways and bidirectional erosion, facilitated by high porosity and feldspar content. In contrast, the clay-rich matrix in siltstones acts as a barrier hindering fluid migration, creating unidirectional erosion in fine sandstones near the interfaces between siltstones and fine sandstones. Ultimately, five evolution processes linking diagenesis with lithofacies assemblages are summarized, highlighting the differential reservoir quality. This study contributes to understanding the mechanism behind diagenetic variations in tight sandstones and the reservoir evaluation. Consequently, it offers geological reference for the development of unconventional oil and gas resources in comparable lacustrine basins.

Seismic coloured inversion to explore the hydrocarbon prospectivity of a field in the Upper Assam basin

This study demonstrates an integrated approach using a seismic-coloured inversion to derive the hydrocarbon potential of a field in the Upper Assam basin. The well-log analysis indicated the presence of hydrocarbon in the form of gas, oil, and water in sandstones with thin streaks of limestone and shale layers. The Acoustic Impedance (AI) model was generated from post-stack seismic data using a coloured inversion. Shale volume (Vshale), density, porosity and water saturation are the petrophysical parameters spatially populated using a multilayered feed-forward neural network on the inversion-based AI model. The estimated range of model-derived parameters varies as Velocity: 2136–5034 m/s, Vshale: 0–48%, Density: 2.14–2.72 gm/cc, Porosity: 6–29%, Water saturation: 9–28%, and demonstrates a reasonable correlation to well-log data. Seismic attribute for thin-fault likelihood was used to interpret the major faults. From the combined analysis based on interpreted faults and modelled parameters, the northwestern part of the study area displays a thick hydrocarbon-bearing zone (due to increasing thickness and reservoir quality). This interpretation is based on the consideration that faults are open. Thus, assuming continuity in the sequence, this northwestern region can be considered as one of the promising candidates for further exploration.

Deep carbonate gas reservoir sweet spot identification with seismic data based on dual-factor control of sedimentary facies and fault system

Deep carbonate reservoirs are attractive targets for gas development. These reservoirs are deeply buried, and commonly possess strong heterogeneity and poor seismic data quality, making the identification of favorable production areas (“sweet spots”) challenging. Furthermore, sedimentary facies and fault systems markedly impact reservoir quality, and identifying these features in seismic data is also crucial for sweet spot identification. To solve these problems, we propose a dual-factor-controlled sweet spot identification method with two steps. First, sedimentary facies and faults are identified separately at different seismic scales using different attributes by the steerable pyramid (SP) method. The SP method decomposes the original seismic data into high-frequency and low-frequency data. The amplitude attributes from high-frequency data are used to identify sedimentary facies, and coherence attributes based on low-frequency data are used to characterize the fault systems. Second, after separately identifying the sedimentary facies and faults, the two attribute volumes are merged together to identify reservoir sweet spots. The results are verified by using well production data. The results of a field study in the Dengying Formation deep carbonate reservoir in the central Sichuan Basin, China, indicate that reservoir sweet spots are primarily developed in ideal sedimentary facies along strike-slip fault systems. Sedimentary facies generally control the type and distribution of reservoirs, whereas strike-slip fault systems control the migration and accumulation of gas. In addition, the fault systems serve as karst channels that further improve the reservoir properties. The proposed dual-factor method might help to maximize exploration potential in deep carbonate reservoirs with similar settings.

Analysis of the Influence of Tambakrigagadung Landfill Leachate Characteristics on Water Quality and Heavy Metal Contamination of Reservoirs, Tikung District, Lamongan Regency

The Final Disposal Site (TPA) of Tambakrigadung Village, Lamongan Regency, implements a semi-sanitary landfill system in which waste processing still piles up piles of waste with soil for a certain period, causing a foul odor due to the leachate that collects. Leachate that is not managed correctly is feared to flow into reservoirs as irrigation and productive land that is used by local communities for rice fields or ponds around the Tambakrigadung TPA so that it can disrupt workers, reduce the quality and yield of rice fields, and affect the development of pond fish around the Tambakrigadung landfill. This research aims to test the quality of reservoir water, which refers to the leachate water quality standards of PermenLHK RI No. P.59 Tahun 2016. It analyzes the influence of leachate on reservoir water around Tambakrigadung. The method used in this research is grab sampling. Analysis of pH, BOD, COD, and TSS parameters using simple linear regression quantitative analysis. Quantitative parameter analysis shows that TPA Tambakrigadung leachate influences the pH and TSS parameters of reservoir water in Tikung District, Lamongan Regency, which is indicated by a significance value of &lt;0.05. The analysis of heavy metal parameters shows that the leachate does not meet quality standards, with a total N of 187.7 ppm and cadmium of 0.15 ppm. The mercury parameter meets quality standards, namely 0.00065 ppm. Meanwhile, heavy metal parameters in reservoir water have met quality standards based on PP No. 22 of 2021.

Extended Laterals and Hydraulic Fracturing Redevelop Tight Fractured Carbonates

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216292, “Redevelopment of Tight Fractured Carbonates Through Extended Laterals and Hydraulic Fracturing,” by Antonio Buono, Cameron Taylor, and Alyssa Dordan, SPE, ExxonMobil, et al. The paper has not been peer reviewed. _ In the complete paper, the authors compare development scenarios in a fractured carbonate play between historic vertical and short horizontal development and modern hydraulically fractured extended lateral development. Because of its long production history and recent redevelopment efforts, the Austin Chalk was chosen as a natural laboratory to test how recent artificial stimulation techniques can lead to additional production from a wider range of pore systems. Development of the Austin Chalk In recent years, application of modern unconventional multistage hydraulic fracturing techniques, coupled with adding proppant to support induced fracture networks, mitigated the steep decline seen in historic production profiles. These improvements were exemplified in a recent Austin Chalk redevelopment where modern completions led to an increase in estimated ultimate recovery (EUR) by 250% on average. In the targeted area of development, historic, short Austin Chalk laterals without modern completions exhibited a wide range of well performance. Some outlier wells achieved high recoveries from accessing an existing natural fracture network with the original completion, whereas others, after only a few months of economic production, were unable to achieve continuous flow without a propped stimulation. The differences in performance partially can be explained by the fact that the reservoir quality of different intervals within the Austin Chalk is likely highly variable. This is exemplified in the B-2 Zone, which contains a well-developed vertical fracture network with variable lengths. Data suggest that the natural fractures are confined within the B-2 and it is geomechanically less-susceptible to wellbore collapse than zones with higher clay concentrations. The B-2 is likely a stiffer interval than the E Zone. This implies that differences exist in the properties of these units that are caused by changes in mineralogy and cementation. The authors aim to characterize reservoir quality and hydrocarbon distributions of the fractured relatively clean zones compared with the hydraulically stimulated reservoir in relatively “dirty” chalky zones, and evaluate geomechanical properties and production expectations from each zone. Depositionally, these units can be characterized broadly as carbonate-rich with subordinate siliciclastic detritus composed of clay minerals and silt-sized quartz and plagioclase grains. These units all contain distinctive stylolite seams. The most-favorable hydrocarbon shows typically are in the lower members of the Austin Chalk. Production data show that natural-fracture-only production (heritage) generally has lower total EUR with highly variable well-to-well production profiles vs. fracture and matrix production, which the authors write that they believe is achieved when unconventional technology is applied to these reservoirs. To project from heritage chalk production to expected EUR using modern completions, the authors used a risked EUR scaling factor of 1.5×. Consequently, the potential uplift in economic viability was recognized through a multiwell Austin Chalk appraisal to assess well-to-well communication with Eagle Ford codevelopment. The authors’ appraisal evaluated reservoir-quality differences between the main landing zones in the Austin Chalk with those from the E Zone of the Austin Chalk and Upper Eagle Ford, respectively, to demonstrate how significant economic uplift can be realized in mature, tight carbonate fields with unconventional technology.

Geophysical evaluation and petrophysical assessment of the Abu Roash "F" Member: A probable unconventional oil reservoir in Heba Field, eastern Abu Gharadig Basin, Egypt

This study investigates the geophysical properties of the Abu Roash F Member (AR/F) as a potential unconventional oil reservoir in Heba Field, located in the eastern region of the Abu Gharadig Basin (Egypt). Analysis of seismic data reveals the influence of Late Cretaceous dextral wrenching tectonic activity, evidenced by the presence of ENE-WSW anticlinal folds and intersecting NW-SE as well as WNW-ESE extensional faults throughout the study area. This tectonic regime is believed to have played a significant role in the formation of micro-fractures within the AR/F carbonate, which can enhance the reservoir's potential by improving its permeability and porosity. Petrophysical assessment identifies favorable reservoir zones within specific depth intervals across multiple wells. These zones exhibit promising reservoir quality, characterized by low shale volume (below 0.20), which indicates a cleaner reservoir rock with less clay content. Additionally, the high total porosity (ranging from 0.20 to 0.25) and moderate effective porosity (ranging from 0.15 to 0.20) suggest that a substantial portion of the rock's pore space is available for storing hydrocarbons. The low water saturation (between 0.40 and 0.50) further supports the presence of hydrocarbons, as it indicates that the pores are not predominantly filled with water. Furthermore, the high hydrocarbon saturation (ranging from 0.50 to 0.60) confirms the significant presence of hydrocarbons within the reservoir. The quantitative assessment of these petrophysical properties across all analyzed wells further confirms the good reservoir quality and potential of the AR/F Member. The integration of seismic and petrophysical data provides a comprehensive understanding of the reservoir characteristics, highlighting the AR/F Member as a significant oil reservoir in the eastern border of the Abu Gharadig Basin, particularly in Heba Field. This study's findings complement the existing knowledge of oil-bearing formations in the region, suggesting that the AR/F Member could be a valuable addition to the basin's hydrocarbon resources. The results underscore the importance of further exploration and development of the AR/F Member to fully realize its potential as a major contributor to the area's oil production.

Dynamic analysis of non-point source pollution in the Sanhekou Reservoir watershed: Implications for sustainable water management

Exogenous pollution, especially non-point source pollution runoff during a flood season, is an important factor affecting the water quality of reservoirs. The Sanhekou Reservoir (Shaanxi, China) is a newly dammed water body, so its non-point source pollution characteristics are unknown. In this study, three major tributaries of the Sanhekou Reservoir watershed were sampled during five rainfall-runoff events in the 2022 flood season. This enabled study of the transport processes of nitrogen, phosphorus, and suspended particles in the runoff under different rainfall conditions. Using hysteresis and redundancy analyses, the sources and transport modes of pollutants are explored here, alongside analysis of rainfall and hydrological characteristics that affect pollutant concentrations, and exploration of land-use relationships. The results showed that (i) nitrate nitrogen and particulate nitrogen were the main forms of nitrogen output, and particulate phosphorus was the main form of phosphorus output. (ii) Total nitrogen, suspended particles, total phosphorus, and particulate phosphorus were significantly affected by maximum rainfall intensity, average rainfall intensity, and average flow rate, whereas nitrate nitrogen and ammonia nitrogen were significantly affected by rainfall duration, rainfall amount, and rainfall-runoff duration. (iii) If 70 % of barren land and cultivated land with slope >15° were converted to forests, total nitrogen, total phosphorus, and suspended particulate loads in the Sanhekou Reservoir would be reduced during the flood season by 10.37 %, 33.01 %, and 45.39 %, respectively. The factors influencing migration and transformation of pollutants during rainfall runoff are important for operational scheduling decisions of reservoirs and guaranteeing quality of the water supply.

Electrofacies-driven 3D-static reservoir modeling of the Late-Cenomanian AbuRoash’G lithounit (Abu-Gharadig Basin, Egypt): Sequence stratigraphic and geomodel constraints for a gas-bearing estuarine system

Estuarine-systems, developed upon transgressive-phases, feature high-quality reservoir-facies, e.g. tidal-bars, that are important stratigraphic-plays critical for hydrocarbon exploration-development. However, capturing their intricate architectural elements (heterogeneity and quality) is still challenging due to the complex stacking-nature and limited-examples. Moreover, defining reservoir-boundaries upon static-modeling of reservoirs cannot be efficient unless it is controlled by stratal-geometries and established depositional-models. To this end, in this study, we performed 3D-static geocellular reservoir-modeling process for the Late-Cenomanian AbuRoash“G” Member (Abu-Gharadig Basin, Egypt) with sequence-stratigraphic and geomodel, relative-geological-time (RGT) model and horizon-stacks, constraints. In this investigation, as an effective-workflow, not only facies-analysis, integrating seismic-stratigraphy and GR-log motifs, was applied for paleo-environment reconstruction, but also machine learning-based electrofacies were applied, through self-organized-maps (SOM), to accurately recognize complex facies-assemblages present. Object-based and pixel-based stochastic-simulation processes were applied upon geocellularly modeling rock and fluid properties, utilizing key-information scales of seismic and well-log data. The results show that three third-order depositional sequences dominate the succession, resting on the Late-Cretaceous unconformity, of which sequence-1 encloses the lowstand and transgressive systems-tracts of the fluvio-estuarine Bahariya and Abu Roash“G” units, respectively. The transgressive phase built AbuRoash“G” lithounit features an estuarine depositional-system encompassing four facies-associations, of which tidal-sand-bars represent significant gas-bearing reservoir-quality facies. The tidal-bar facies’ efficient reservoir quality calls for attention and testing in future development plans and investigation in similar settings. Furthermore, the facies-constrained workflow established in this study, for reservoir modeling, can worldwide help identify the ultimate reservoir-configuration, as long as the 3D-static modeling process is controlled by the stratal and geomodel restraints.

Siliciclastic Reservoir Geo-modeling using TGS-SIS hybrid algorithm of the Upper Cibulakan Formation, Offshore Northwest Java Basin

Abstract The Upper Cibulakan is the primary hydrocarbon-producing formation in the Offshore Northwest Jawa area, operated by PHE ONWJ (Pertamina Hulu Energy Offshore Northwest Jawa). The productive interval in this formation comprises alternating sandstone and shale up to 45 feet of thick. Geologically, this interval is a shallow marine deposit with strong influence of tidal in the Ardjuna Sub-Basin, offshore part of Northwest Jawa Basin. The good quality reservoir layer is associated with Tidal Sand Ridges (TSR) facies characterized by lenticular sedimentary structures and the occurrence of shale intercalation in sandstone. The occurrence of shale, regarding its facies association package, varies greatly and significantly determines the quality of the reservoir. The geometry and quantity of facies distribution and association will significantly affect the calculation of hydrocarbon reserves during the modelling processes. Considering this, the selection of modeling methods and algorithms must be carried out appropriately. The use of the SIS (Sequential Indicator Simulation) algorithm in describing the TSR facies distribution still has shortcomings in randomness. Correspondingly, it requires to be combined with the TGS (Truncated Gaussian Simulation) method as it plays a great impact in calculating the distribution of sandstone and reservoir geometry. Meanwhile, SIS defines shale intercalation within TSR facies. Combining these two methods produces a more precise model of TSR facies associations. Besides, the concept of reservoir deposition is easier to explain based on the outcome result from the combined methods.

Lithofacies, changes in mineral composition and reservoir properties of the Maykopian sediments in the Yevlakh-Aghjabedi Depression

Yevlakh-Aghjabadi depression is a well explored oil province located in the Middle Kura basin between Greater and Lesser Caucasus.The study investigates the lithofacial, mineralogical, and collector properties of the Maykopian sedimentary series within the Yevlakh-Aghjabadi depression, focusing on the Oligocene to Early Miocene epoch. Maykop deposits are widely distributed in the foothill regions of the Lesser Caucasus, both at the surface as natural outcrops and in the geological structure of deeper formations. In this article, in addition to core samples, the results of fieldworks have also been widely discussed. The conducted research indicates favorable paleogeographic conditions for oil and gas presence in these depressions. The sedimentary sequence, up to 2200 meters thick, is divided into Lower and Upper Maykopian subgroups, showing fluctuating thickness distribution. The primary source of clastic materials for the Maykopian suit is the Lesser Caucasus Mountain range. The lithological composition consists of clay, sandstones, and conglomerates, influenced by paleogeographic changes and paleochannels. Collector properties vary, with Lower Maykopian sediments exhibiting better characteristics, especially in the south-western part of the basin. The mineralogical composition dominated by fine-grained feldspars, impacts reservoir quality. Maykopian suits in the oil and gas regions of Ganja and Muradkhanli, which encompass the southernwestern and northern-eastern flanks of the Yevlakh-Aghjabedibasin, as well as conducting extensive research on reservoir properties, will enable the proper direction of future exploration activities. For this purpose, the overall condition of the Maykopian suits and the distribution of lithofacies have been analyzed, and the characteristics of hydrocarbon reservoirs have been determined. Keywords: lithology; lithofacies; Maykopian; sandy and clayey sediments; argillaceous sandstones; porosity; permeability.

Impacts of sedimentary characteristics and diagenesis on reservoir quality of the 4th member of the Upper Triassic Xujiahe formation in the western Sichuan basin, southwest China

The 4th member of Xujiahe Formation (Xu4) in the western Sichuan Depression is a typical porous tight sandstone reservoir. Finding reservoirs with relatively high porosity controlled by sedimentation and diagenesis is crucial for successful tight gas exploration. In this study, the Xu4 sandstone was studied by diverse methods, including outcrop and core observation, logging data interpretation, thin section and cathodoluminescence examination, scanning electron microscopy analysis, and X-ray diffraction, to determine sedimentary and diagenetic characteristics and to discuss their impact on the sandstone reservoir quality. During the depositional period of Xu4, subaqueous distributary channel sandstone of braided river delta front developed extensively under controls of bidirectional provenance (LASP and SASP), mainly consisting of litharenite and sublitharenite, with low feldspar and high rock fragments volume, respectively. Strong compaction and carbonate cementation have largely destroyed primary porosity, while secondary pores constitute the main pore space in the Xu4 sandstone. The sediment provenance, sedimentary microfacies and A/S determine the clastic composition of sandstone, genetic type and thickness of sand bodies, furthermore affect the subsequent diagenetic variations. The larger the thickness of the sand body indicates a higher-energy depositional environment, coarser grain size, better sorting, and lower shaliness content of the sandstone during deposition period. This results in stronger resistance to compaction of the sandstone, which is conducive to the preservation of primary pores and dissolution of organic acids, resulting in better physical properties of sandstone. Among them, the physical properties of the sandstones of the Xu4s and Xu4x are better than those of the Xu4z; moreover, LASP's sandstone is superior to SASP. It is worth noting that subaqueous distributary channel sandstones with thickness exceeding 13 m in Xu4s and Xu4x from LASP represent favorable areas for high-quality reservoirs. The work can be used as a reference for the exploration and evaluation of similar tight sandstone gas in the world.

Pre-Jurassic weathering crust of the Kalinovoe hydrocarbon deposit, Tomsk region: composition and structure characteristics

Abstract. The study of pre-Jurassic deposits in the southwestern part of Western Siberia is highly relevant due to their potential of increasing hydrocarbon resources. These deposits are considered prospective targets for the discovery of hydrocarbon accumulations. Weathering crusts developed on the upper part of the Paleozoic rocks in the Tomsk region exhibit a complex composition and structure, reflecting the interplay of various factors, including primary sedimentary processes and later alteration processes, including fracture-controlled fluid flow and metasomatism. Aim. To establish the characteristics of the mineralogical composition and structure of the Paleozoic weathering crust formations developed at the Kalinovoe oil-gas-condensate field. Methods. Optical microscopy, X-ray diffraction, scanning electron microscopy. Results and conclusions. The composition and structure of the deposits at the boundary zone between the Paleozoic and Mesozoic successions have been studied in detail in the section of one of the wells at the Kalinovoe oil-gas-condensate field. The factual material is represented by core and thin sections of weathering crust deposits. The primary rock-forming minerals are silica minerals (quartz, chalcedony and opal) and clay minerals, with a lesser amount of carbonate minerals (siderite). Different lithological units were identified based on the content of minerals and bioclast (radiolarians and sponge spicules), indicating their formation under marine conditions. The protoliths of the altered rocks were carbonate-siliceous rocks, argillaceous limestones, and radiolarian cherts, which as a result of multiple stages of hydrothermal alteration and metasomatic processes were transformed into argillaceous-silicified rocks. In these rocks, with intense post-alteration overprinting, good reservoir quality porosity can develop. This porosity includes biogenic voids, microcavities, micropores, and open fractures.

Abu Roash F reservoir hydrocarbon potential, Western Desert, Egypt

The Western Desert of Egypt is recognized for its significant potential in oil and gas reserves, making it a prominent hydrocarbon-producing area with conventional reservoirs. Recent findings from various wells suggest that unconventional reservoirs in the Western Desert may hold considerable promise. The primary objective of this study was to explore this potential. Accordingly, a comprehensive and multidisciplinary approach has been employed to assess the Abu Roash/F (AR/F) reservoir. The methodology involved meticulously examining formation characteristics and integrating borehole images with existing core data and thin sections. This integration aimed to analyse and interpret the lithofacies of the reservoir, with a specific focus on identifying fractures and decoding potential diagenesis effects. As a result, we successfully identified wells exhibiting optimal reservoir quality, unveiling the presence of fractured dolomite or vuggy dolomite in wells containing promising oil and gas pay intervals. Notably, some wells displayed low porosity (3%), yet seismic attribute maps in their vicinity indicated a high density of fractures. This underscores the importance of combining borehole images with seismic attributes to evaluate carbonate formations effectively. The fractures, predominantly oriented NW–SE, were found to be associated with deformation zones. Our findings emphasize the critical role of this integrated approach in unlocking the full potential of hydrocarbon reservoirs in the Western Desert.

The controlling effect of sedimentary characteristics on the heterogeneity of the Chang 6 reservoir in the Wuliwan area

The sedimentary system of the delta front is complex. The hydrodynamic conditions, changes in sediment supply, and mineral composition are crucial factors that influence the quality of reservoirs. Reservoir quality varies among different sedimentary units. In this field of research, there is a general tendency to mainly use core data and logging curves for reservoir characterization and prediction, while neglecting the combination with the microscopic scale of the reservoir. This article proposes a new method to characterize reservoir heterogeneity by studying the sedimentary characteristics of reservoirs. This method uses casting thin-section data to aid in core and logging research. This study consists of five parts: core analysis, casting thin-section study, logging facies study, geological analysis, and single-well prediction. Combining macroscopic and microscopic methods helps clarify the controlling effect of sedimentary characteristics on reservoir heterogeneity. The research results indicate that this research method effectively solves the challenge of characterizing reservoir heterogeneity in the middle and later stages of development of low-permeability reservoirs. The research outputs serve as valuable references for the advancement of analytical matching fields.